Message-ID: <21072837.1075842500611.JavaMail.evans@thyme> Date: Wed, 21 Jun 2000 09:11:00 -0700 (PDT) From: drew.fossum@enron.com To: stephen.thome@enron.com Subject: Re: Pueblo Mime-Version: 1.0 Content-Type: text/plain; charset=us-ascii Content-Transfer-Encoding: 7bit X-From: Drew Fossum X-To: Stephen Thome X-cc: X-bcc: X-Folder: \Drew_Fossum_Dec2000_June2001_1\Notes Folders\Sent X-Origin: FOSSUM-D X-FileName: dfossum.nsf Great--Steve, what's your phone no. ? The operator didn't have it and I'd like to talk for a few minutes on this. Thanks. DF Stephen Thome@ECT 06/20/2000 04:20 PM To: Drew Fossum/ET&S/Enron@ENRON cc: William Gang/HOU/EES@EES@ECT, John M Rose/ENRON_DEVELOPMENT@ENRON_DEVELOPMENT@ECT, Bill Votaw@ECT, Jerry D Martin/ENRON_DEVELOPMENT@ENRON_DEVELOPMENT@ECT, Arnold L Eisenstein/ENRON_DEVELOPMENT@ENRON_DEVELOPMENT@ECT, Steven Harris/ET&S/Enron@Enron, Lorraine Lindberg/ET&S/Enron@ENRON, Kevin Hyatt/ET&S/Enron@Enron, Christopher F Calger/PDX/ECT@ECT Subject: Re: Pueblo Here are some peaker data points: Two LM6000's in simple cycle configuration can be installed for between $43 m and $50 m, providing a total of 80 MW. Looking at a 10 year deal, there is no way to recoup this value and ENA would not be willing to take the back 10 years on its books without an offtaker. If EES or DOE were willing to step up for 20 years, there might be an opportunity. Assuming a 9700 heat rate, $3 per MWh O&M, and NYMEX plus $0.39 for gas, the spread option for a peaker at 4 Corners would be worth between $33 m and $47 m. The first number represents the intrinsic value, and the second is inclusive of an option premium. ENA's desk (EPMI) would pay somewhere in between. Having just inquired with the desk regarding their appetite for taking positions (short 65 MW, long 80 MW) in Albuquerque, they were luke warm. Considering transmission constraints into Albuquerque, their bid offer spread might run the range of the extrinsic value on the 65 MW load. Depending on site conditions (available infrastructure), a barebones LM6000 plant could make economic sense. The plant host would likely need to pay some sort of premium for generation reliability. EES could sell fixed priced energy with a reliability premium to the DOE. ENA would back-to-back the EES contract, managing market price risk and economically optimizing the peaker. As a stand-alone market play, a peaker is marginal at best. By receiving value for reliability, the project might have merit. Based on the thin margins, I am skeptical that we would want to build a plant larger than the host's load... that is more MW than that amount on which we could expect to receive some sort of demand charge. Ultimately, the demand charge needs to make up the shortfall between EPMI's swap value and the cost of the plant. Steve Enron North America Corp. From: Drew Fossum @ ENRON 06/19/2000 08:27 AM To: Stephen Thome/HOU/ECT@ECT cc: William Gang/HOU/EES@EES@ECT, John M Rose/ENRON_DEVELOPMENT@ENRON_DEVELOPMENT@ECT, Bill Votaw@ECT, Jerry D Martin/ENRON_DEVELOPMENT@ENRON_DEVELOPMENT@ECT, Arnold L Eisenstein/ENRON_DEVELOPMENT@ENRON_DEVELOPMENT@ECT, Steven Harris/ET&S/Enron@Enron, Lorraine Lindberg/ET&S/Enron@ENRON, Kevin Hyatt/ET&S/Enron@Enron Subject: Re: Pueblo Thanks for the extremely helpful analysis Steve and John. I'm getting a pretty clear sense that this project isn't going anywhere as it is currently configured. Just to satisfy myself, though, let me throw out a couple of observations for the group to react to, along the lines of Steve's "However" section of his memo: 1. Running this thing as a baseload unit won't work. The fuel cost is a killer. However, I keep thinking about the $200/mwh 4 Corners spot price someone mentioned on the phone. Is there enough volatility at 4 Corners to support a peaking merchant plant? How often are those types of opportunities available, and could a power plant in Alb. capture that upside by transporting power to 4 Corners over PNMs system? 2. We have been assuming that the power plant should be a baseload plant. Someone on the phone last week had some numbers indicating that the DOE/DOD electric load at Kirtland had a fairly high load factor. I think we have all assumed further that the plant should run at a high load factor to sell surplus power into the grid (either at 4 Corners or, after N.M. elec. restructuring, into the Alb. area). I just found the numbers I was remembering on the conf. call--1998 peak load was 63.6 mw, and total annual 1998 consumption was 334.5 million Kwh. By my lawyer-math, that is about a 60% load factor for DOE. If the DOE load is only 60% L.F., and the plant only generates surplus power when it can capture profit opportunities that arise when the market clearing price at 4 Corners or in Albuquerque exceeds some benchmark rate ($.05/Kwh? $.10/Kwh? higher?) the plant might run at a 30-40% load factor on an annual basis. The question is can we reduce the capital cost significantly by building a peaker instead of a baseload unit? 3. Could we get debt financing for a 140 mw plant that had a baseload demand charge contract for only 65 mw (i.e., DOE) but sold the rest of its output into the grid only when profit opportunities arose? 4. If the answer to 3. is no, would ENA backstop the debt financing by signing a demand charge contract for all surplus power over and above what the government needs? At what price? Based on its knowledge of volatility and profit opportunities currently available at 4 Corners, and future profit opportunities that will be available in Albuq. is that just a dumb bet, or would ENA get interested if someone else (i.e., DOE) split the risk and reward? John, how much of the information in your analysis could be sanitized in a way that we could provide it to Dennis Langley? If we pull the plug on the project, I'd like to be in a position that we could let him in on some of our information on why the turbines we would use can't provide acceptable economics. I don't expect that we'd want to disclose the swap value analysis in Steve's memo, however. Thanks again, and I'd appreciate anyone's reaction to the above questions. DF Stephen Thome@ECT 06/16/2000 06:12 PM To: William Gang/HOU/EES@EES cc: John M Rose/ENRON_DEVELOPMENT@ENRON_DEVELOPMENT, Bill Votaw@ECT, Jerry D Martin/ENRON_DEVELOPMENT@ENRON_DEVELOPMENT, Arnold L Eisenstein/ENRON_DEVELOPMENT@ENRON_DEVELOPMENT, Steven Harris@ENRON, Drew Fossum@ENRON, Lorraine Lindberg@ENRON Subject: Re: Pueblo John's proposed plant costs are consistent with what we have seen for our ongoing LM6000 development. I have priced 130 MW at Four Corners assuming Permian gas plus 50 cents for transport. This also assumes $4.70 per MWh for O&M and an 8000 heat rate. For an hourly 7x24 product, the intrinsic value of the gas-power swap is $52.5 million on a 20 year deal, well below the $108 million estimate of constructing the facility. A ten year swap is worth only $42 million (NPV = -66 m ). That implies a market mid-price of $34 per MWh levelized over the period. Using the ENA Power and Gas structuring model and curves, we can determine the following: 1. New build gas turbines cannot compete against the New Mexico market on price. 2. LM6000 CCGT efficiency gain does not pay for HRSG and ST over a ten year period. However: 1. Transmission constraints could create market value in Albuquerque that does not exist at Four Corners. 2. ENA's power prices typically undersell the market. 3. Commodity pricing does not accurately value capacity or reliability in constrained markets. If Enron wants to do a deal in Albuquerque, we should be selling capacity and reliability. Given the number of power- critical industries in the area, we could look at siting several remote units at different locations in the city. Numerous chip manufacturing facilities and the Kirtland base could support several LM6000's for power reliability that is specific to their installations. I might also suggest that peaking units would have advantages over CCGT units. Existing generation already provides ample baseload supply, however, the production of peak and intermediate energy is not necessarily well suited to existing units. LM6000's have exceptionally good ramp rates that provide real value to a utility customer. Not only can the HRSG/ST hinder the flexibility of the units, it can add substantial capital and operating expense with little real market benefit. We should also explore the ability to schedule load. If the DOE wants to peak for a test, would it be willing or able to schedule a test for the off-peak hours? Under those circumstances, we might be able to cut them a break on power and provide reliability of supply. Steve Thome 503-464-3708 John M Rose@ENRON_DEVELOPMENT 06/15/2000 06:53 PM To: Bill Gang@EES cc: , Stephen Thome@ECT Subject: Pueblo Bill, Yesterday, we decided to look at two options for Pueblo; a 60 MW case and a 140 MW case. In order to match these outputs as closely as possible with available equipment, I made the following selections: Case 1 Equipment 3 X GE LM 2500 Gas Turbine Generators with Heat Recovery and 1 X 22 MW Steam Turbine Generator Output at 95 deg F & 5000 ft 67 MW Output at avg. conditions (60 deg F) 73.4 MW Heat Rate at avg. conditions 8170 Btu/kWh (HHV) Case 2 Equipment 3 X GE LM 6000 Gas Turbine Generators with Heat Recovery and 1 X 44 MW Steam Turbine Generator Output at 95 deg F & 5000 ft 130 MW Output at avg. conditions (60 deg F) 143.7 MW Heat Rate at avg. conditions 7900 Btu/kWh (HHV) There is a wide fluctuation in ambient temperature in Albuquerque and I sized the blocks based on 95 deg F but used the annual average output at 60 deg F for estimating power sales. I have attached files that show the build-up of the estimated EPC price for the plants. The required power prices are projected in a simple-minded economics file attached. The projections are based on: 70% debt financing at 10% rate. 10-year project and debt life. 8500 hours per year at average output (97% capacity factor). Gas at $4.40/MMBtu. The results turn out pretty much as anticipated. Even with the larger plant, we'd have to sell the power for over 6c/kWh.